This invention relates to a pressure pulse generator. Such a pressure pulse generator is usable in particular in the area of drilling, and more specifically in a logging-while-drilling and/or measuring-while-drilling tool.
In these techniques, drilling is accomplished using a string of drillpipe that terminates in a drilling tool. The logging and/or measuring tools are located near the drilling tool, downhole, in a drillpipe in the string. Logging or measurement data are transmitted to the surface.
There are various existing methods of achieving this transmission. It may be achieved through electrical signals using the electrical conductors that pass through the drillpipe string. Transmission may also be achieved through acoustic signals transmitted through the drillpipes in the string. These methods permit a relatively high transmission flow rate. But the former of these techniques is relatively expensive to implement and poses problems for the connection of the conductors at the joint between drillpipes in the string. As for the latter, it lacks reliability due to the high degree of noise generated during drilling.
A conventional data transmission technique uses the drilling fluid as a means of transmitting depth-modulated acoustic waves representative of the logging and/or measurement tool response.
FIG. 1 illustrates a drilling device capable of making such logs and/or measurements. This device can be equipped with a pressure pulse generator according to the invention.
A drilling fluid 1 contained in a tank 14 is injected by a pump 4 from the surface 2 to the inside of a drillpipe string 3 intended to drill into a geological formation 7. The drilling fluid 1 arrives at a drill bit 5 at the end of the drillpipe string 3. The drilling fluid 1 exits the drillpipe string 3 and returns to the surface 2 through the space 6 between the drillpipe string 3 and the geological formation 7. The route of the drilling fluid 1 is illustrated by the arrows.
One of the drillpipes 3.1 in the drillpipe string 3 that is near the drill bit 5 is instrumented. This instrumented drillpipe 3.1 contains at least one measurement device 8 intended among other things to evaluate the physical properties of the geological formation, such as its density, porosity, resistivity, etc. This measurement device 8 is part of a logging-while-drilling or LWD tool 13.
When this measuring device 8 measures drilling-related parameters such as temperature, pressure, drilling tool orientation, etc., it is part of a measuring-while-drilling or MWD tool.
The instrumented drillpipe 3.1 is generally a drill collar. This is a drillpipe that is heavier than the others. It applies sufficient weight to the drill bit 5 to drill into the geological formation 7.
In order to produce a pressure fluctuation in the drilling fluid 1, and thereby transmit data, a pressure pulse generator 9 is placed in the instrumented drillpipe 3.1 just above the area that contains the measurement devices 8. The pressure pulse generator 9 is part of a telemetry module 12 whose function is to control data transmission between the downhole measurement device 8 and the pressure sensors 10 at the surface. The telemetry module 12 is part of the logging- and/or measurement-while-drilling tool.
U.S. Pat. No. 3,309,656 describes a rotating pressure pulse generator. Rotating at a constant speed, it partially but repeatedly interrupts the flow of the drilling fluid 1. The interruptions cause the pressure pulse generator to generate pressure pulses at a carrier frequency that is proportional to the interruption rate. Accelerating or decelerating the generator modulates the phase or the frequency of the pressure waves to transmit the data associated with the measurements made by the measurement device 8 to the surface 2. Pressure sensors 10 at the surface 2 receive the pressure waves that are propagated in the drilling fluid 1. Before being demodulated, the acoustic signal representing the pressure waves sensed at the surface is filtered in a processing device 11 to eliminate the noise which is inevitable. The assembly formed by the telemetry module 12 including the pressure pulse generator 9, the processing device 11, and the pressure sensors 10 is hereinafter called the “telemetry system.”
Due to the drilling fluid, which is generally mud, the acoustic signal recovered at the surface is highly attenuated. This limits the performance of pressure pulse telemetry systems.
Although rotating pressure pulse generators have been improved in the past ten years, they still have weaknesses. U.S. Pat. No. 6,219,301 describes a conventional but more recent pressure pulse generator. Referring to FIGS. 2A and 2B, the pressure pulse generator 9 shown has a stator 20 with several peripheral orifices 21 and a rotor 22 with blades 23 in the form of a cross. The rotor 22 is rotated near the stator 20 by a motor (not shown). The drilling fluid, whose displacement is illustrated by the arrows in the figures, goes through the peripheral orifices 21 of the stator 20. As the rotor 20 rotates it partially blocks the stator orifices 21 and either significantly restricts the passage of the fluid or else allows it to pass massively. In FIG. 2A, the pressure pulse generator is in the so-called “open” position. The rotor blades 23 do not coincide with the orifices 21 and the flow of fluid through the pressure pulse generator is maximal. A communicating area can be defined for the fluid passage, corresponding to the stator orifices, for example triangles whose sides are approximately 20, 30, and 30 millimeters.
In FIG. 2B, the pressure pulse generator is in the so-called “closed” position. The rotor blades partially block the orifices 21 of the stator 20 and the fluid flow through the pressure pulse generator is minimal. The pressure pulse generator does not totally prevent the passage of the fluid. Since this fluid serves to lubricate the drilling tool, it is necessary for it to permanently circulate in the drillpipe string so that drilling operations can continue. When the blades 23 of the rotor 22 are opposite the stator orifices 21, the orifices 21 have an unblocked space 24. The communicating area for the fluid is the spaces 24, for example rectangles approximately 28×4 millimeters.
As the rotor 22 rotates, it generates a fluid flow downstream of the pressure pulse generator in which the pressure falls and rises at the rate of rotation. The pressure pulses generated by the generator rotate at constant speed and are not perfectly sinusoidal. As can be seen in FIG. 4, these pulses are represented with the reference A in FIG. 4. A perfect sinusoid is referenced B. Clipping occurs. Energy is lost in the form of harmonics. These harmonics can interfere with the demodulation of the signal at the surface.
Inevitably, the fluid contains solid particles or debris. In order to be easily removable, this debris must not be too large because it must pass through the peripheral orifices 21 of the stator 20. Since larger debris often appears, the drive motor must be powerful enough so that the rotor can grind it up. When the debris is ground up, it can then be discharged. But grinding up this debris may cause wear to the rotor. If the motor power is not sufficient, the pressure pulse generator seizes and clogs, and this can cause the drillpipe string to be clogged.
In an effort to provide necessary power, pressure pulse generators have been used in combination with turbines. U.S. Pat. No. 5,517,464 describes an integrated modulator and turbine-generator with a turbine impeller coupled by a drive shaft to a modulator rotor downstream from the impeller. The turbine impeller is used to drive the modulator rotor, which is coupled to an alternator. Despite this advancement in downhole energy conservation, there is an ever-increasing need for more power in downhole operations. What is needed is a system that is capable of channeling and/or utilizing the force of fluid flowing through the generator to create additional power.